System and method for using time-distance characteristics in acquisition, processing, and imaging of t-CSEM data

ABSTRACT

There is provided herein a system and method of acquiring, processing, and imaging transient Controlled Source ElectroMagnetic (t-CSEM) data in ways that are similar to those used for seismic data. In particular, the instant invention exploits the time-distance characteristics of t-CSEM data to permit the design and execution of t-CSEM surveys for optimal subsequent processing and imaging. The instant invention illustrates how to correct t-CSEM data traces for attenuation and dispersion, so that their characteristics are more like those of seismic data and can be processed using algorithms familiar to the seismic processor. The resulting t-CSEM images, particularly if combined with corresponding seismic images, may be used to infer the location of hydrocarbon reservoirs.

RELATED APPLICATION

This application claims the benefit of U.S. Provisional PatentApplication Ser. No. 60/654,378 filed on Feb. 18, 2005, the disclosureof which is incorporated by reference as if fully set out at this point.

TECHNICAL FIELD

This invention relates to the general subject of geophysical explorationfor hydrocarbons and, in particular, to methods for collecting andanalyzing time-domain controlled source electromagnetic earth surveydata.

BACKGROUND OF THE INVENTION Electro-Magnetic Exploration Methods

Measurements of resistivities of subsurface Earth formations have longbeen used, among other purposes, for differentiating rock layers thatcontain hydrocarbons from other, non-oil bearing rock layers. Forexample, records of resistivity with respect to depth in a wellbore(called “resistivity well logs”) have been routinely used for many yearsto identify hydrocarbon producing intervals within a well bore drilledthrough Earth formations. However, more recently, surface-based surveysof subsurface resistivity have been utilized that do not require that awell be drilled. See, for example, U.S. Pat. Nos. 4,286,218, 4,617,518,4,663,593, 4,757,262, 4,792,761, 4,862,089, 5,043,667, 5,467,018,5,563,513, 5,770,945, 6,191,587, 6,603,313, 6,628,119 B1, 6,696,839 B2,6,717,411 B2, 6,842,006 B2, 6,900,639, 6,914,433; U.S. PatentApplication Publications Nos. 2003/0050759 A1, 2004/0239297 A1,2005/0017722 A1, 2005/0077902 A1). Such techniques instead includemaking measurements from the Earth's surface that are subsequently usedto infer the subsurface resistivity distribution, (Strack, K.-M., 1992,Exploration with deep transient electromagnetics, Elsevier, 373), ormaking such measurements at the surface of or on the bottom of a body ofwater. It is the latter sort of survey that is of most interest forpurposes of the instant disclosure.

Although surface-based resistivity surveys come in a number of differentforms, there are two main variants: natural-source (magnetotelluric,“MT”) surveys, and controlled-source (“CSEM”) surveys, wherein by“controlled-source” is meant any artificial source. As discussed below,it is the latter sort of survey that is of most interest for purposes ofthe instant disclosure.

Note that some surface-based EM surveys operate at very high frequency,in which case the source waves propagate in the earth according to boththe dielectric constant of the earth material and the subsurfaceresistivity. Such survey techniques are called “ground penetratingradar” and typically investigate only to depths of a few meters (cf.,Everett, 2005, M. E., Benavides, A., and Pierce, C. J., 2005, Anexperimental study of the time-domain electromagnetic response of aburied conductive plate, Geophysics 70(1)). In order to investigatedeeper into the earth (i.e., in the hydrocarbon context discussedherein), it is necessary to use lower frequencies (<10 Hertz), in whichcase the waves propagate according to the resistivity only. The termCSEM as used herein shall refer only to such low-frequency surveys.

CSEM surveys generally utilize as a signal source a surface-generatedelectrical current that is introduced into the Earth's subsurfacethrough one or more electrodes, or “lines of contact.” (Some sources areinstead current loops that inject electromagnetic energy into the Earth,not by conduction, but by induction; we concentrate here on the former.)The one or more electrodes might either be placed in direct contact withthe surface of the Earth (e.g., in a land survey) or towed behind a boatthrough the water above the ocean floor (e.g., in a marine survey), orplaced in contact with the ocean floor. Receivers are positioned on theEarth's surface (or on the ocean bottom) and are arranged to measure theelectric and/or magnetic fields that are introduced into the Earth'ssubsurface by the source. These measurements are used to estimate thedistribution of effective or apparent resistivity of the Earth'ssubsurface beneath the receivers according to methods well known tothose of ordinary skill in the art. These resistivities are theninterpreted, by those skilled in the art, in terms of hydrocarbonoccurrence. Note that depending on the signal source and survey design,the receivers might be situated at distances from zero to 20 kilometersaway from the source.

Generally speaking, the Earth's subsurface has relatively fewlarge-contrast resistivity boundaries between adjacent rock formations.However, rock formations that contain hydrocarbons tend to show a largeresistivity contrast (in comparison with the formations that enclosethem) and, as a consequence, surface-based resistivity survey methodshave long been viewed as potential direct hydrocarbon indicators. Forexample, the resistivity of a hydrocarbon bearing formation could be onthe order of a few tens of Ohm-meters (Ohm-m) or higher, as comparedwith the resistivity of over- and under-lying water-saturated sediments,which have resistivity on the order of 2 Ohm-m or less. Thus, whenhydrocarbons are present in the Earth's subsurface, surface-basedresistivity survey methods potentially can be used to detect them whenother geophysical methods might not. As a consequence, there iscurrently a great deal of interest in using surface-based resistivitysurvey methods to locate new sources of trapped hydrocarbons, to monitorthe hydrocarbon distribution within an existing reservoir (e.g.,reservoir monitoring over time), etc.

Although there are a number of resistivity survey variants, ofparticular interest for purposes of the instant disclosure are surveysthat utilize an artificial source, or controlled source, (i.e.,controlled source electro-magnetic measurements, or “CSEM”,hereinafter). See, for example, U.S. patents: U.S. Pat. Nos. 4,617,518,4,663,593, 5,467,018, 5,563,513, 5,883,515, 6,541,975, 6,603,313,6,628,110, 6,628,119 B1, 6,696,839 B2, 6,717,411 B2, 6,842,006 B2,6,891,376, 6,900,639, 6,914,433; and U.S. Patent ApplicationPublications Nos: 2003/0050759 A1, 2004/0239297 A1, 2004/232917,2005/0017722 A1, 2005/0077902 A1; WIPO Application Publications Nos: WO01/57555 A1, WO 03/023452, WO 03/048812). This technology mostfrequently is operated in a marine environment, with a boat pulling asubstantially horizontally disposed electric dipole electrode or antennaarray near the sea bottom, above a set of sea-bottom receivers. Thereceivers can be autonomous nodes, or arrays cabled in some fashion. Theantenna or electrode array is coupled to a suitable electric powergenerator that is situated on the boat (collectively “the source”).

As the source is towed in the vicinity of the set of receivers,electromagnetic energy propagates from source to receiver, via a varietyof paths (e.g., through the water, though the earth, along thewater/earth interface, etc), and the variations in the amplitude andphase of these fields are detected and recorded by each of thereceivers. The receivers are subsequently recovered from the sea floor,and the data are collected. Various processing algorithms are then usedto determine the spatial resistivity distribution of the Earth'ssubsurface beneath the position of the receivers.

The source is usually programmed to create a low-frequencyelectromagnetic signal by varying the voltage that is supplied to theelectric dipole. In some variations, alternating currents are employedas the signal source, with the polarity of such current being reversedat a selected frequency. Any such surveying, with a continuouslyenergized source operating at one or a few selected frequencies ishereinafter called frequency-domain controlled-source electromagneticsurveying (“f-CSEM”). f-CSEM techniques are described, for example, inSinha, M. C. Patel, P. D., Unsworth, M. J., Owen, T. R. E., andMacCormack, M. G. R., 1990, An active source electromagnetic soundingsystem for marine use, Marine Geophysical Research 12, 29-68, thedisclosure of which is incorporated by reference herein as if fully setout at this point.

In the marine context, the more widely used CSEM acquisition methods usefrequency-domain techniques and, more particularly, use a continuoussource that operates at one or a few discrete frequencies. Srnka, U.S.Pat. No. 6,603,313, the disclosure of which is incorporated herein byreference, discusses a good example of such f-CSEM survey techniques,citing therein several other recent patents and publications sharingthis same class of techniques.

Another controlled-source technique for surface-based resistivitysurveying is known as transient (or time-domain) controlled-sourceelectromagnetic surveying, called “t-CSEM” hereinafter. In t-CSEM, anelectrode array or antenna array is used to induce an electromagneticfield in the Earth's subsurface in the same general manner as wasdiscussed previously in connection with f-CSEM, except the sourcecurrent is operated in fixed-duration impulses (separated by enough timeto allow for signal propagation within the Earth prior to a repeatedimpulse), rather than continuously as for f-CSEM. See, for exampleEdwards, R. N., 1997, On the resource evaluation of marine gas hydratedeposits using the sea-floor transient electric dipole-dipole method,Geophysics, 62, 63-74; Yu, L., and Edwards, R. N., 1996, Imagingaxi-symmetric TAG-like structures by transient electric dipole seafloorelectromagnetics, Geophys. Res. Lett., invited paper, 23, 3459-3462;Nobes, D. C., Law, L. K., and Edwards, R. N., 1992, Results of aseafloor electromagnetic survey over a sedimented hydrothermal area onthe Juan de Fuca Ridge. Geophysical Journal International, 110, 333-347;Chave, A. D., Constable, S. C. and Edwards, R. N., 1991, Electricalexploration methods for the seafloor, Investigation in geophysics No 3,Electromagnetic methods in applied geophysics, vol. 2, application, partB, 931-966; Cheesman, S. J., Law, L. K., and Edwards, R. N. 1991;Porosity determinations of sediments in Knight Inlet using a transientelectromagnetic system, Geomarine Letters 11, 84-89; Cheesman, S. J.Edwards, R. N., and Law, L. K., 1990, A short baseline transientelectromagnetic method for use on the seafloor, Geophysical Journal 103,431-437, and others.

In t-CSEM techniques, the electrodes or antennas may be charged using adirect current (“DC”) source that after some selected time is shut off,causing an abrupt termination of the electric current. This transient EMevent propagates into the subsurface, and eventually to the receivers.Data are collected from the receivers during the time interval after thesource current is switched off. Predictably, such data reflect a generaldecay in the measured voltages, as time progresses subsequent to thesource termination. Note that this is in contrast to f-CSEM methodswhich collect data from the receivers while the source current isflowing. The time variation of the voltages that are measured after thetermination of the source current is used to infer the resistivitydistribution of the Earth's subsurface. T-CSEM techniques are described,for example, in Strack, K.-M., 1992, cited previously, the disclosuresof which are incorporated herein by reference as if fully set out atthis point. For the most part, t-CSEM techniques have typically beenused in connection with land surveys (see, for example, Everett, 2005,cited previously, for an application in the context of exploration forunexploded ordinance, or Strack, K.-M., Vozoff, K., 1996, Integratinglong-offset transient electromagnetics (LOTEM) with seismics in anexploration environment, Geophysical Prospecting 44, 99-101, for asummary of hydrocarbon applications).

Note that although f-CSEM methods are more widely used in hydrocarbonexploration (than are t-CSEM techniques), they have significantdrawbacks. For example, marine f-CSEM is best applied when the water isrelatively deep as compared to the depth of the subsurface formationsbeing evaluated, more specifically when the ratio of the depth of thewater to the (sub-seafloor) depth of the target formations (orreservoir) is greater than about 1.5. By contrast, the t-CSEM methodstaught in the foregoing disclosures have no such limitations.

Since the signal that is detected by the receivers in CSEM techniquesafter traveling through the Earth's subsurface is very low in amplitude,it may be detected more readily if the source itself is no longeractive. This, of course, constitutes an advantage for t-CSEM surveys,wherein the source is deactivated while data is collected from thereceivers. Thus, if the source signature is continuous (or of longduration) rather than transient (or of short duration), the sourcesignal may mask the voltage variations that might be caused bydifferences in the subsurface lithology. Wright (Intl Pat. Appl. WO03/023452) and Rueter et al. (U.S. Pat. No. 5,467,018), which disclosureis incorporated herein by reference, contains a good discussion oft-CSEM methods, particularly in the land context.

The Seismic Method

Although the instant invention is directed principally toward theacquisition, analysis, and processing of controlled sourceelectromagnetic data, a brief overview of some salient aspects of thegeophysical reflection seismic method will prove instructive to thediscussion that follows. A reflection seismic survey represents anattempt to image or map the subsurface of the Earth by sending soundenergy down into the ground and recording the echoes that return fromthe rock layers below. The source of the down-going sound energy mightcome, for example, from explosions or seismic vibrators on land, or airguns in marine environments. During a seismic survey, the energy sourceis placed at various locations near the surface of the Earth above ageologic structure of interest. Each time the source is activated, itgenerates a seismic signal that travels downward through the Earth, isreflected, and, upon its return, is recorded at a great many receiversdisposed on or near the Earth's surface. Signals from multiplesource/recording geometry combinations are then combined to create adensely sampled profile of the subsurface that can extend over asubstantial subsurface area. In a two-dimensional (2-D) seismic survey,the recording locations are generally disposed along a single line,whereas in a three dimensional (3-D) survey, the recording locations aredistributed across the surface in a grid pattern. In simplest terms, a2-D seismic line can be thought of as giving a cross-sectional picture(vertical slice) of the Earth layers as they exist directly beneath aline drawn through the recording locations. A 3-D survey produces a datavolume that is a 3-D representation of the subsurface that lies beneaththe survey area. In reality, though, both 2-D and 3-D surveysinterrogate some volume of earth lying beneath the area covered by thesurvey.

A seismic survey is composed of a large number of individual seismicrecordings or traces. In a typical 2-D survey, there will usually beseveral tens of thousands of traces, whereas in a 3-D survey the numberof individual traces may run into the multiple millions of traces.Chapter 1, pages 9-89, of Yilmaz, 1987, contains general informationrelating to conventional 2-D processing and that disclosure isincorporated herein by reference. General background informationpertaining to 3-D data acquisition and processing may be found inChapter 6, pages 384-427, of Yilmaz, the disclosure of which is alsoincorporated herein by reference.

A seismic trace is a digital recording of the acoustic energy reflectingfrom inhomogeneities or discontinuities in the subsurface. A partialreflection typically occurs wherever there is a change in the elasticproperties of the subsurface materials. The digital samples in a traceare usually acquired at 0.002 second (2 millisecond or “ms”) intervals,although 4 ms and 1 ms sampling intervals are also common. Each discretesample in a conventional digital seismic trace is associated with aparticular time with respect to the actuation time of the seismic energysource. In the case of reflected energy, a two-way travel time from thesource to the reflector and back to the surface again, assuming (ofcourse) that the source and receiver are both located on the surface, isassociated with particular amplitude events in the traces. Manyvariations of the foregoing source-receiver arrangement are used inpractice, e.g. VSP (vertical seismic profile) surveys, ocean-bottomsurveys, etc. Furthermore, the surface location of the source andreceiver associated with every trace in a seismic survey is carefullyrecorded and is generally made a part of the trace itself (as part ofthe trace header information). This allows the seismic informationcontained within the traces to be later correlated with specific surfaceand subsurface locations, thereby providing a means for posting andanalyzing seismic data—and attributes extracted therefrom—on a map(i.e., “mapping”).

Over many decades, the art of seismic survey design has advancedconsiderably, and modern practitioners use the time-distancecharacteristics expected of the data to optimally design the survey, forthe purposes of subsequent analysis. By the phrase time-distancecharacteristics, is meant those characteristics of EM data that varywith the amount of natural time since the initiation of the source (timeof propagation from source to receiver), and with the relative positionsof the sources and receivers (vector or scalar distance between sourceand receiver). Examples of seismic design consideration that involve thetime-distance relationship include, without limitation, such issues asreceiver positioning, source positioning, array filtering, the attitudeof structural elements within the subsurface, the frequencies in thedata, etc. Note that, for purposes of the instant disclosure, when theterm “distance” is used herein that term should be broadly construed toinclude vector distances, scalar distances, or both depending on thecontext.

Similarly, over many decades the art of seismic processing has advancedconsiderably, and modern practitioners once again use the time-distancecharacteristics of the data to optimally process such data. Examples ofseismic processes that exploit samples of a trace according to an offsetand a time (the time-distance relationship) include, without limitation,velocity filtering, frequency-wavenumber (“f-k”) filtering,intercept-slowness (“tau-p”) filtering, initial trace mute (i.e.,zeroing each trace for all samples earlier than the first signalarrival), amplitude variation with offset (i.e., “AVO”), velocitydetermination, tomography, etc.

Further, over many decades, the art of seismic imaging has advancedconsiderably, and modern practitioners use the time-distancecharacteristics of the data to optimally image it. “Imaging” is theprocess of constructing band-limited (“fuzzy”) images directly from thedata (either in 2-D or 3-D, according to the survey design). (Imagingmay be contrasted with “inversion”, which is the process of using thedata to evaluate the parameters of a pre-conceived model.) Additionalexamples of seismic processes that exploit the time-distancerelationship include, without limitation, Normal MoveOut (“NMO”)removal, Dip MoveOut (“DMO”) removal, migration (time or depth),tomography, velocity estimation, etc.

For example, the simplest form of imaging is called common-midpointstacking, wherein the reflected arrivals (acquired with fit-for-purposeacquisition design, and perhaps cleansed of noise) are sorted intoCommon Mid Point (“CMP”) gathers, that is, a group of traces withacquisition geometry in which the mid-points (between the sourcepositions and the receiver positions) are the same, corrected fordifferences in arrival time (the “moveout”) of reflective events forvarious offsets (distance between the source and receiver for eachacquired trace), and then summed together (“stacked”). A moresophisticated type of processing is common-image-point stacking, whereininformation about the subsurface wave-propagation paths is incorporatedto tailor the sorting and moveout-correction to specific subsurfacereflector(s) of interest.

The time-distance corrections that are applied to seismic data typicallyinvolve determination of a velocity function, which function is usuallyempirically determined from the data, and that is variable in 1, 2, or 3spatial dimensions (or in both space and time). Although seismicvelocities may be determined in many different ways, two commonly usedtechniques are coherency analysis and tomographic analysis.

Seismic data that have been properly acquired and processed can providea wealth of information to the explorationist, one of the individualswithin an oil exploration company whose job it is to locate potentialdrilling sites. For example, a seismic survey can provide theexplorationist a broad view of the subsurface structure of the rocklayers and can often reveal important features associated with theentrapment and storage of hydrocarbons such as faults, folds,anticlines, unconformities, and sub-surface salt domes and reefs, amongmany others. During the computer processing of seismic data, estimatesof subsurface rock acoustic velocities are routinely generated, andnear-surface inhomogeneities in the rock properties are detected anddisplayed. In some cases, seismic data can be used to directly estimaterock porosity (fractional volume of pore space in the rock), watersaturation (fractional volume of the pore space that is water-filled),and hydrocarbon content (fractional volume of the pore space that ishydrocarbon-filled). In other techniques, seismic trace waveformattributes such as phase, peak amplitude, peak-to-trough ratio,Amplitude versus Offset, and a host of others, can often be empiricallycorrelated with known hydrocarbon occurrences, and that correlation canbe applied to seismic data collected over new exploration targets.

Although all of these seismic techniques are well developed, understood,and often very effective, there remain many geologic contexts where theyare less effective, for a multitude of reasons. Heretofore, as is wellknown in the geophysical prospecting and interpretation arts, there hasbeen a need for a method of using non-seismic techniques to obtain aresistivity image of the subsurface that does not suffer from thelimitations of the prior seismic art. Accordingly, it should now berecognized, as was recognized by the present inventors, that thereexists, and has existed for some time, a very real need for a method ofgeophysical prospecting using t-CSEM that would address and solve theabove-described problems.

Before proceeding to a description of the present invention, however, itshould be noted and remembered that the description of the inventionwhich follows, together with the accompanying drawings, should not beconstrued as limiting the invention to the examples (or preferredembodiments) shown and described. This is so because those skilled inthe art to which the invention pertains will be able to devise otherforms of this invention within the ambit of the appended claims.

SUMMARY OF THE INVENTION

According to a preferred aspect of the instant invention, there isprovided a system and method of acquiring, processing, and imagingt-CSEM data, in the hydrocarbon context(s) of exploration, appraisal,development, and surveillance, in ways that are similar to those usedfor seismic data. In particular, the instant invention exploits thetime-distance characteristics of t-CSEM data to permit the design andexecution of t-CSEM surveys for optimal subsequent processing. In moreparticular, one aspect of the instant invention exploits thetime-distance characteristics of t-CSEM data traces to permit the use ofmost seismic processing algorithms on t-CSEM data traces, in ways thatare similar to those used for seismic data. In further particular, theinstant invention exploits the time-distance characteristics of t-CSEMdata to permit, for the first time, the application of various imagingalgorithms to properly acquired and processed t-CSEM data. The instantinventors have discovered that the transient nature of the t-CSEM sourcecreates data records that are similar in many respects to those acquiredduring a reflection seismic survey. In fact, after appropriateprocessing via the methods disclosed herein, the t-CSEM data traces maybe treated very similarly to seismic traces for purposes of dataenhancement, imaging, and interpretation.

EM wave propagation in this context differs from seismic wavepropagation in that the propagation is strongly attenuative, and highlydispersive (i.e. the velocity is highly frequency dependent). Suchpropagation can be described as “diffusive”. These characteristicsimpede, and sometimes preclude, the successful application of the ideasintroduced above. Hence in another preferred aspect of the instantinvention, there is provided a method for correcting t-CSEM data for theeffects of attenuation and dispersion, in order to exploit moreeffectively the ideas introduced above. As a consequence, the data mayreadily be processed and imaged via standard reflection-seismicalgorithms. Although the resulting images will have less resolution thando seismic images, they will indicate resistivity distributions in thesubsurface, and hence (after geologic interpretation), they can providea more direct indication of the presence of hydrocarbons. In conjunctionwith conventional seismic images of the same subsurface volume, thebenefits of both techniques may be realized.

According to a further preferred embodiment, there is providedhereinafter a method of correcting the attenuation and dispersion oft-CSEM data that makes such amenable for processing withreflection-seismic-style algorithms thereafter. In more particular, inthe preferred embodiment the instant method corrects attenuation at eachfrequency according to its square root, and corrects for dispersionusing Q=½.

Finally, for purposes of the instant invention it should be noted thatthe term “time-distance” processes will be broadly construed to includethose processes that potentially treat each sample in a tracedifferently, depending on the natural time of occurrence of that samplewithin the trace (and of course, the source-receiver distance, etc.). By“natural” time, we mean that measure of time which is normallyunderstood, by lay persons and scientists alike, and which appears inall the governing equations of (non-relativistic) physics. Note that itis important that, as compared with the prior art, that the algorithmoperate in natural time (e.g., the recorded time axis will not beentransformed to log-time). If, as in some of the prior art (e.g.,Ziolkowski and Hobbs, 1998, CMP method applied to multichannel transientelectromagnetic data, 60^(th) EAEG conference, Leipzig, Germany,Extended Abstracts, Paper 10-05), the data were transformed tologarithmic time, then, in general, seismic processing could not beapplied, since this is a non-linear transformation (i.e., if thestarting-point of time were changed, the results would be different).Non-linear operations on EM data should generally be avoided, as thetransformed data no longer obeys the underlying physics equations.

The foregoing has outlined in broad terms the more important features ofthe invention disclosed herein so that the detailed description thatfollows may be more clearly understood, and so that the contribution ofthe instant inventors to the art may be better appreciated. The instantinvention is not to be limited, in its application, to the details ofthe construction and to the arrangements of the components set forth inthe following description or illustrated in the drawings. Rather, theinvention is capable of other embodiments and of being practiced andcarried out in various other ways not specifically enumerated herein.Finally, it should be understood that the phraseology and terminologyemployed herein are for the purpose of description and should not beregarded as limiting, unless the specification specifically so limitsthe invention.

BRIEF DESCRIPTION OF THE DRAWINGS

Other objects and advantages of the invention will become apparent uponreading the following detailed description and upon reference to thedrawings in which:

FIG. 1 illustrates the general environment of the instant invention.

FIG. 2 illustrates a seismic processing sequence suitable for use withthe instant invention.

FIG. 3 contains an illustration of a preferred acquisition logic.

FIG. 4 illustrates a preferred t-CSEM processing logic.

FIG. 5 contains a logic diagram of a preferred t-CSEM imaging logic.

FIG. 6 contains a preferred operating logic for t-CSEM gain correction.

FIG. 7 illustrates the general environment of the instant acquisitioninvention.

FIG. 8 illustrates how a central frequency might be selected.

FIG. 9 contains an idealized t-CSEM response to the subsurfacehydrocarbon reservoir of FIG. 7.

FIG. 10 conceptually illustrates how the instant invention operates totransform t-CSEM data to data that are comparable to reflection seismicdata.

DETAILED DESCRIPTION

While this invention is susceptible of being embodied in many differentforms, there is shown in the drawings, and will herein be describedhereinafter in detail, some specific embodiments of the instantinvention. It should be understood, however, that the present disclosureis to be considered an exemplification of the principles of theinvention and is not intended to limit the invention to the specificembodiments or algorithms so described.

General Environment of the Invention

FIG. 1 illustrates a general environment in which the instant inventionwould typically be used. Following survey-design principles describedbelow, t-CSEM data are collected in the field 110 (while the preferredembodiment is in the marine context, it is not restricted to such andcan include land, and borehole, and combined applications) over oralongside a subsurface target of potential economic importance for theexploration and exploitation of hydrocarbon resources, and are typicallysent thereafter to a data processing center. Either in the field 110 orin the data processing center a variety of preparatory processes 120might be applied to the data traces to make them ready for use by themethods disclosed hereinafter. In most cases, each recorded data tracewill be associated with at least an X and a Y coordinate on the surfaceof the earth (or relative to some other coordinate system) that marksthe location of the physical receiver that was used to record thattrace. Further, it is also typical to pair each recorded trace with a Zvalue that represents its elevation relative to some arbitrary datum.The processed traces would then be made available for use with theinstant invention and might be stored, by way of example only, on harddisk, magnetic tape, magneto-optical disk, DVD disk, or any other massstorage means known in the art.

The methods disclosed herein would best be implemented in the form ofcomputer programs 140 that have been loaded onto a general-purposeprogrammable computer 150 where they are accessible by a seismicinterpreter or processor. Note that a general-purpose programmablecomputer 150 would typically include, in addition to mainframes andworkstations, computers that provide for parallel and massively parallelcomputations, wherein the computational load is distributed between twoor more processors. As is also indicated in FIG. 1, in some preferredembodiments a digitized zone of interest model 160 would be specified bythe user and provided as input to the processing computer program 140.In the case of a 3-D survey, the zone of interest model 160 wouldtypically include specifics as to the lateral extent and thickness(which might be variable and could be measured in time or depth) of asubsurface volume of interest. The exact means by which such zones arecreated, picked, digitized, stored, and later read during programexecution is not critical to the instant invention and those skilled inthe art will recognize that this might be done any number of ways.

A program or programs 140 embodying the instant invention might beconveyed into the computer by means of, for example, a floppy disk, amagnetic disk, a magnetic tape, a magneto-optical disk, an optical disk,a CD-ROM, a DVD disk, a RAM card, flash RAM, a RAM card, a PROM chip, orloaded over a network. Accordingly, the manner of storing and loadingthe program 140 into the computer 150 is not a limitation on the scopeof this invention.

After t-CSEM data have been subjected to the processes discussed herein,the resulting information would typically displayed either at ahigh-resolution color computer monitor 170 or in hard-copy form as aprinted section or a map 180. The geophysical interpreter would then usethe displayed images to assist in identifying subsurface featuresconducive to the generation, migration, or accumulation of hydrocarbons.

Turning now specifically to the processing and interpretation ofgeophysical seismic data, in a typical seismic processing environmentthe seismic data would be subjected to a variety of processes beforethey are given to the interpreter. FIG. 2 illustrates in a general waythe sorts of processes that might be applied to conventionally acquiredseismic data. Further, and as is discussed in greater detail below, onekey aspect of the instant invention is that after suitable correctionfor dispersion/attenuation, t-CSEM data can be treated for all practicalpurposes as if they were seismic data, provided that they have beenproperly acquired and processed. Hence, the processes of FIG. 2, asdiscussed below, may be applied in substantial degree to t-CSEM data.

Those of ordinary skill in the art will recognize that the processingsteps illustrated in FIG. 2 are only broadly representative of the sortsof processes that might be applied to EM or seismic data and the choiceand order of the processing steps, and the particular algorithms thathave been selected may vary markedly depending on the individual seismicprocessor, the signal source (dynamite, vibrator, etc.), the surveylocation (land, sea, etc.) of the data, the preferences of the companythat processes the data, etc.

As a first step, and as is generally illustrated in FIG. 2, in theseismic arts a 2-D or 3-D seismic survey is conducted over a particularvolume of the earth's subsurface (shown at 210) that contains one ormore geologic features of interest, the goal being to obtain informationrelated to the target feature. The seismic data collected in the fieldconsist of unstacked (i.e., unsummed) seismic traces which containdigital signals representative of the volume of the earth lying beneaththe survey equipment. Methods by which such data are obtained andprocessed into a form suitable for use by seismic processors andinterpreters are well known to those of ordinary skill in the art.

After seismic data are acquired, they are typically taken to a dataprocessing center where some initial or preparatory processingprocedures are applied to them. As is illustrated in FIG. 2, a commonearly procedure, shown at 215, is designed to edit the input seismicdata in preparation for subsequent processing (e.g., digitization,demultiplexing, wavelet shaping, bad trace removal, etc.). This might befollowed by specification of the geometry of the survey (shown at 220)and storing of a shot/receiver number and corresponding surfacelocations as part of each seismic trace header. Once the geometry hasbeen specified, it is customary to perform a velocity analysis and applyNMO (Normal MoveOut) adjustment to correct each trace in time to accountfor signal arrival-time delays caused by variations in offset.

After the initial pre-stack processing is completed, it is common tocondition the seismic signal that is located within the unstackedseismic traces (step 230). In FIG. 2 at 230 a typical “SignalProcessing/Conditioning/Imaging” processing sequence is performed, butthose skilled in the art will recognize that many alternative processescould be used in place of the ones listed in FIG. 2. In any case, theultimate goal, from the standpoint of the explorationist, is theproduction of a stacked seismic volume or, in the case of 2-D data, astacked seismic line for use in the exploration for hydrocarbons withinthe subsurface of the earth.

As is suggested in FIG. 2, any digital sample within a stacked seismicvolume is uniquely identified by a coordinate triplet (X, Y, TIME), withthe X and Y coordinates representing the geodetic position of thereceiver on the surface of the Earth (or the sea floor), and the timecoordinate representing a recorded natural arrival time within theseismic trace (shown at 240), and a corresponding coordinate doublet (x,y) representing the position of the source. For purposes of specificity,when speaking of 3-D data volumes it will be assumed that the Xdirection corresponds to the “in-line” direction, and the Y measurementcorresponds to the “cross-line” direction, as the terms “in-line” and“cross-line” are generally understood in the seismic art. Althoughnatural time is a preferred and most common vertical axis unit, thoseskilled in the art understand that, as a result of the final imagingstep, other units are certainly possible, including, for example, depth.

The explorationist may perform an initial interpretation 250 of theresulting stacked volume, wherein the principal reflectors and faultsare located and identified within the data set. This might be followedby additional data enhancement 260 and/or attribute generation (shown at270) of the stacked or unstacked seismic data. In many cases, theexplorationist will revisit the original interpretation in light of theadditional information obtained from the data enhancement and attributegeneration procedures (shown at 280). As a final procedure, theexplorationist will typically use information gleaned from the seismicdata together with other sorts of data (magnetic surveys, EM surveys,gravity surveys, LANDSAT data, regional geological studies, well logs,well cores, etc.) to locate subsurface structural or stratigraphicfeatures conducive to the generation, migration, or accumulation ofhydrocarbons (i.e., prospect generation 290).

Preferred Embodiments

The instant invention is broadly founded on the observation that thetransient nature of t-CSEM data creates data traces that are in somesense analogous to those created by the impulsive sources of thereflection seismic method. This can include a separate or jointacquisition and treatment of seismic and t-CSEM data. It has furtherbeen discovered that, especially if t-CSEM data are properlyconditioned, they take on the time-distance characteristics of seismicdata, and can thereafter be processed using most algorithms that wouldbe suitable for use with stacked or unstacked seismic data. Further, andafter such proper conditioning, the resulting t-CSEM traces may betreated similar to reflection seismic traces for purposes of dataenhancement, subsurface imaging, and geophysical interpretation.

Turning now to FIG. 7, wherein a preferred acquisition arrangement isillustrated, preferably the data for the instant invention will beacquired with a boat 705 towing an electromagnetic source (an antenna)710 below the surface of the ocean 715 in the proximity of receivers 725(and, optionally, additional receivers 735) that have been placed on theocean floor 720. The target of interest 730 is most likely to be one ormore rock units that may contain hydrocarbons trapped therein. As isindicated in FIG. 7, the electromagnetic energy generated by the source710 propagates outward from the source, through the water and throughthe subsurface rocks by various pathways, until some of it eventuallyencounters the receivers. If a hydrocarbon reservoir is present in thesubsurface (as is generally illustrated by reservoir unit 730 of FIG.7), some of the energy will be reflected and/or refracted off thereservoir and back to the receivers. Although in the preferredarrangement, the instant invention will be most frequently utilized inmarine settings, that is not a requirement, and land surveys thatimplement the techniques discussed herein are specifically within theambit of the instant invention.

The energy that is sensed by receivers 725/735 is converted toelectrical and/or optical signals, and these signals are typicallyrecorded in equipment (not shown separately) associated therewith. Therecording equipment as shown is subsequently retrieved and interrogatedwhen the receivers 725/735 are recovered. However, the receivers canalso be in a streamer or ocean-bottom cable, and recordings might betransmitted via wire or telemetry to a recording station (not shownseparately) that might be in the boat 705 that pulls the source, or in adifferent boat, or on a stationary platform, etc. On land, the recordingstation would likely be located within a vehicle that is situatedproximate to the survey. Irrespective of where the recording station islocated, its primary function is to read the digital information fromthe receivers 725/735 and store that information for later review and/ortransmission to a remote processing facility. Of course, those ofordinary skill in the art will recognize that significant processing oft-CSEM data may be done in the field so the procedure of moving therecorded data to a processing center should be regarded as optional forpurposes of the instant invention.

As is conceptually illustrated in FIG. 9, data traces 910 can be readilydisplayed with respect to (natural) source actuation time on thevertical axis (preferably with the time axis increasing toward thebottom of the page) and with the observed voltage (“V+”) in each tracebeing plotted on the horizontal axis. In the particular example of FIG.9, a “step-down” t-CSEM source signal pattern has been utilized, and theimpulse response can be extracted from the raw data by differentiation(as is well known to those skilled in the art). Of course, the resultantsignal voltages tend to decrease in amplitude, within each trace (as afunction of natural time), and across traces (as a function of distancefrom the source), i.e., a time-distance characteristic. Within the traceshown is water-born energy (traveling at water velocities), andsubsurface energy (traveling at sediment velocities). The exactvelocities depend upon the resistivity of the medium, the frequencycontent of the energy, and the propagation path (e.g., direct orreflected or refracted).

According to a first aspect of the instant invention 300 and as isgenerally indicated in FIG. 3, there is provided a system and method foracquiring t-CSEM data that allows the data so-collected to be utilizedand interpreted as though it were conventional reflection seismic data.As a first procedure 305, a survey is designed that is customized toimage a particular subsurface target (e.g., rock unit 730 which maycontain trapped hydrocarbons). Among the many parameters that might beconsidered in formulating the survey design are:

-   -   the depth of the target formation;    -   the 3-D structure of the target formation (including its 2-D or        3-D dip, if any);    -   whether the survey design will utilize a conventional “end on”        configuration (e.g., whether only the receivers 725 that are        behind the boat or only those ahead 735 will be recording) or a        “split spread” configuration (i.e., both receivers 725 and 735        will be recording), or an oblique-shooting design, wherein the        sources are located off the line(s) of receivers.    -   the maximum offset (i.e., the distance from the source 710 to        the most distant active receiver 725/735) and minimum offset        (i.e., the distance from the source 710 to the closest active        receiver 725/735);    -   the inter-receiver 725 spacing; etc.;    -   the source-point spacing;    -   the relation between source points and receiver points (e.g.        source points near to receiver points, source points midway        between receiver points, etc.);    -   the frequencies expected in the received data;    -   the strength of the sources, and the source signature (e.g.,        step-off, pseudo-random binary sequence, etc.); and    -   the sensitivity of the receivers.

Those of ordinary skill in the seismic art will recognize that theforegoing parameters are routinely considered in the context of aseismic survey. But in the typical t-CSEM context heretofore, most ofthe foregoing parameters are not considered in survey design, nor aresuch considerations resolved in a way to optimize further seismic-styleprocessing and imaging of the data. f-CSEM survey design considerations,as disclosed for example by Srnka (U.S. Pat. No. 6,603,313), are notrelevant here, as they do not depend upon time-distance characteristics,but only upon distance characteristics. Further, most t-CSEM practicehas been concerned with designing surveys to image relatively simple(e.g., 1-D targets) and the typical number of receivers used in suchsurveys is so small that proper design is not possible.

As is the case with conventional seismic surveys, it is critical thatthe EM data be acquired so as to be unaliased in space and time. Thatis, those of ordinary skill in the art will understand that aliasingoccurs when a target is sampled temporally or spatially at a frequencythat is above the Nyquist frequency with respect to the frequencycontent or target dimensions. When speaking with reference to temporalaliasing, the sample rate is key and the choice of that parameter mustbe made in view of the frequency bandwidth of the signal source, theexpected subsurface velocities, the likely thickness of the subsurfacetarget, the attitude (strike and dip) in 3-D space, and other factorswell known to those of ordinary skill in the seismic arts. When speakingwith reference to spatial aliasing, such factors as source/receiverspacing, distance from the source to the near and far offsets, thenumber of receivers, etc., can be varied—and often are varied in theseismic context—to guard against under sampling the subsurface.Depending on the estimated dip of the target in the subsurface, its sizeand depth, the velocities expected to be encountered, the desiredFresnel zone size at the target, etc., there are well known rules ofthumb in the seismic arts that provide guidance as to which surveyparameters should chosen to produce an unaliased survey.

In the context of EM surveys, however, such concerns have not heretoforebeen addressed in a general framework, and this is especially true inthe case of lateral resolution. Thus, it should be noted that anotheraspect of the instant invention is the design of unaliased EM surveysaccording to principles of seismic survey design. That is, given anestimate of the subsurface EM velocities (see below) and an estimate ofthe depth, dimensions, and, orientation of the target, the instantinventors prefer that standard seismic rules of survey design be appliedto determine the EM survey parameters including, as specific examples,the receiver spacing, the number of receivers, and distance from thesource to the near- and far-offset receivers.

As a next preferred procedure 310, the receivers 725/735 will be placedon either the ocean floor or the surface of the earth (depending uponwhether the survey is on land or offshore), according to the specifiedsurvey design. Note that one advantage of the instant t-CSEM approach isthat much closer offsets can be utilized than would be necessary in thecase of, for example, f-CSEM surveys. As a specific example, with manyf-CSEM surveys the formation-related signals detected by the receiversnearest the source are typically overwhelmed by the direct signal fromthe source and, thus, are rendered essentially useless for purposes ofsubsurface exploration. With typical f-CSEM surveys, the usefulreceivers are likely to be positioned at distances of about 3-10 km fromthe source. However, the instant invention can utilize receivers thatare located at distances between zero and 3 kilometers from the source.This is possible because t-CSEM methods activate the source and thenthereafter deactivate it, so that signals can be collected from thereceivers during periods of time in which no energy is emanating fromthe source, thus minimizing difficulties from the so-called “direct”signal, and the so-called “air wave”.

In one preferred embodiment, the source will be moved along a line ofreceivers 725/735 (FIG. 7), but in other embodiments the receivers725/735 will be laid out in a 2-dimensional pattern across the surfaceof the earth (or on the water bottom), thereby yielding a 3-D image ofthe subsurface when the data have been properly collected, organized,processed, and analyzed. Note that a 3-D arrangement of receivers, suchas the foregoing, is heretofore not known in the t-CSEM (or f-CSEM)arts, but is well known in the reflection seismic arts.

Note that, in 3-D P-wave seismics, the source is usually a monopole(radiating equally in all azimuths), whereas in 3-D CSEM, the source isusually a horizontal dipole (radiating differently in differentazimuths). In this respect, the 3-D t-CSEM survey is more like a 3-Dshear-wave survey, in which the polarization direction of the source iscritical (cf, e.g., Thomsen, L., 1988, Reflection Seismology inAzimuthally Anisotropic Media, Geophysics, 53(3), 304-313.), and similarsurvey-design considerations apply. For example, the resulting(X,Y,TIME) data at each receiver may be linearly transformed, at eachTIME, into (RADIAL, TRANSVERSE, TIME) data, using a trigonometrictransform well known to those skilled in the seismic arts, so that thenew RADIAL component points in the horizontal azimuth from source toreceiver, and the new TRANSVERSE component is perpendicular to that,with a specific “right-handed” chirality convention.

In 2-D EM surveys, the “shots” (i.e., activations of the source 710)will preferably be taken when the source is above or proximate to one ofthe receivers 725/735, thereby creating the possibility (as is discussedmore fully hereinafter) of organizing the information so-recorded into“common mid point” (CMP) or “common image point” (CIG) gathers as istypically performed in seismic data acquisition. In 3-D EM surveys,approximate CMP or CIG gathers may be constructed by “binning”procedures, similar to those used in 3-D seismic surveys. Of course,organization of individual EM trace recordings from a 2-D or 3-Dreflection seismic survey into CMP or CIG gathers is well known in theseismic arts.

As a next preferred procedure 315 (FIG. 3), data will be acquired byactivating the sources 710 (FIG. 7) and recording the voltages that aresensed at the receivers 725/735. The preferred source 710 is ahorizontally disposed wire, grounded at both ends to the Earth or to thewater, connected to an electric generator that can be controlled so asto provide an impulsive source signature, or a signature that can beprocessed to yield the equivalent of an impulse. In one preferredarrangement, a “step down” signal will be generated (i.e., directcurrent to the transmitter antenna or electrodes will be turned on foran extended period, then abruptly turned off) and the resulting voltagesrecorded during the period that follows.

However, it has been recognized that more complex transmitter signalsmight be utilized than the simple “step down” function or similarsignals known to those in the t-CSEM arts. As a first specific example,a pseudo-random series of short binary pulses will be generated by thesource, with the receivers 725/735 continuously recording while theentire series of pulses is generated. Of course, it is anticipated thatadditional processing will be required to benefit from this sort ofsignal. Those of ordinary skill in the art will recognize how such asource could be utilized with conventional seismic data and the sorts ofoperations that would be necessary to remove the effect of the extendedsource signal from the recorded data. After application of theprocessing methods discussed hereinafter, such seismic-based methodswill be appropriate for use with the voltage vs. natural time recordingspreferably obtained from the EM receivers. Note that the use of such apseudo-random series of pulses, further treated with the processingmethods discussed hereinafter to create an impulsive source signature,is heretofore unknown in the t-CSEM arts.

In still another preferred arrangement, a frequency sweep (analogous tothe sweeps that are commonly utilized by vibrators during landseismic-data acquisition) will be generated by the source. That is, thecurrent that is applied to the source 710 will be in the form ofsine-wave alternating current swept through a range of frequencies,preferably beginning with a predetermined upper frequency and endingwith a predetermined lower frequency (e.g., an downward sweep over afrequency range of about 10 Hz to 0.1 Hz). As was mentioned previously,it is anticipated that the recorded data will undergo post-acquisitionimpulse-equivalent signal recovery analogous to the cross-correlationtechniques that are used with seismic vibrator data, includingcorrections for attenuation and dispersion before or after suchimpulsive-signal recovery. Note that such a source signal is heretoforenot known in the t-CSEM arts.

As a next preferred procedure at 320 (FIG. 3), the data acquired at 315will be processed in such a fashion that thereafter they can beinterpreted in a manner similar to that of conventional seismic data.The importance of this procedure will be discussed in greater detailbelow but, in brief, after processing at 320 according to the methodstaught herein, the recorded t-CSEM data will resemble and may generallybe interpreted in the same manner as reflection seismic data.

Finally, the data will preferably be displayed and/or interpreted (at325) for the purpose of locating subsurface rock units that containtargets that are of potential economic interest for their hydrocarboncontent. As is conceptually illustrated in FIG. 10, the t-CSEM datatraces 920 will preferably be corrected by the methods of the instantinvention for dispersion/attenuation, producing traces that can beprocessed as if they were natural time-domain seismic traces 1010.Further, and in a noise-free environment, such t-CSEM data would beexpected to yield a clear image of the dipping hydrocarbon reservoir730, after the manner of seismic imaging. Note that the reservoir 730 isshown in phantom in FIG. 10 because it would not normally be a part ofthe seismic data display. It has only been added to FIG. 10 to makeclearer the character of its expression in the data after processing bythe methods taught herein.

In the case of exploration for hydrocarbons, the ultimate goal is tolocate economic quantities of trapped oil and/or gas within thesubsurface. That being said, it is possible that the invention describedherein could be used to locate other sorts of targets (e.g., minerals,etc.). Note that data that are so acquired, processed, and displayedwill resemble conventionally acquired reflection seismic data. Accordingto another preferred embodiment, there is provided a data processingmethod 400 (FIG. 4) that transforms raw t-CSEM data so that it can beprocessed similarly to those of conventionally acquired seismic data,taking advantage of its time-distance characteristics. That is, naturaltime t-CSEM data show the time-distance characteristics of seismic dataand, after treatment according to the methods taught herein, areamenable to processing by any number of seismic processing algorithmsknown in the art. Note that, to realize these processing steps, the datamust not be transformed to logarithmic time, as is taught by Ziolkowskiand Hobbs, 1998, cited previously.

As is indicated in FIG. 4, in a first preferred procedure the inputt-CSEM data that were previously acquired (at 315 in FIG. 3) will beread. Note that the data that are read at 405 may not be the actualt-CSEM data traces that were recorded in the field, but, instead, mightbe a representation of that original data (e.g., the original data mayhave been filtered, amplified, etc., according to methods well known tothose of ordinary skill in the art). Hence, for purposes of specificityin the text that follows, it will be assumed that the data being read at405 might have been pre-processed in appropriate ways. Note, that thissame comment should be understood to also apply to the other methodsdiscussed herein that similarly begin by reading t-CSEM data traces asinput, e.g., in FIG. 6, at 605. It is preferable, and often mandatory,that any such preprocessing be linear, in the mathematical sense.

As a next preferred procedure (to the extent such has not been performedalready), various pre-processing algorithms will be applied to therecorded t-CSEM data. As specific examples of the sorts of algorithmsthat might be applied, it is preferable that the acquisition geometryinformation be determined for each t-CSEM trace (i.e., preferably eacht-CSEM trace will be associated with specific locations on the Earth,indicating where the receiver that acquired that data was located, andwhere the source was located). Other operations that might be performedat this stage include sorting (e.g., into common-mid-point gathers),gain recovery (see, e.g., 425, hereinafter), time-variant gain controletc.

As a next preferred step, at 415, the impulse response will be recovered(if necessary) from the recorded t-CSEM data. Note that whether or notthis procedure will be performed will depend on the source signaturethat was used to acquire the data. If the data are obtained by recordinga “swept” signal (as was discussed previously), a cross correlationwould likely be performed between a pilot signal (usually obtained froma “near field” receiver or sensor or, in some cases, the actual inputsource signal could be used) and the recorded t-CSEM data. On the otherhand, if the source signal was a “step off” signal, it would beappropriate to calculate a first time derivative of the input datatraces. Alternatively, a linear filter might be applied to approximatelyshape the source signature into an impulse, using methods well known tothose skilled in the seismic arts.

Next, the instant method will preferably determine a velocity functionfor the data according to methods well known in the seismic arts (step420) and apply noise reduction of the sort that would typically beapplied to 2-D or 3-D seismic data (at 418). Usually the data are notsubstantially free of noise at this point in the process. The data maybe contaminated by many different types of noise, some of which can belargely eliminated or attenuated by means familiar to those skilled inthe seismic arts. These means are additional to noise-attenuationtechniques specific to electromagnetic data (cf., e.g., Strack, 1992,cited previously). In particular, there is likely to be (at least in themarine context) source-generated water-borne noise, which is preferablyattenuated or separated from the signal of interest at this point in theprocessing sequence. Also, there will likely be source-generated noiserefracted at the water-sediment interface (the water bottom), andperhaps in the near subsurface. All such noise typically arrives at thereceivers with a different apparent velocity (a time-distancecharacteristic) than the reflected/refracted signal that arrives fromthe subsurface. Therefore, since the data will preferably have beenacquired with a suitable survey design, such noise may be attenuated bya variety of algorithms that are familiar to those skilled in theseismic arts. For example, an f-k (frequency-wave number) filter mightbe applied to remove coherent noise, or a tau-p (intercept-slowness)filter could be used to restrict the range of dips present in the data,a velocity filter could be used to attenuate events traveling in certainvelocity ranges, a mute could be applied to remove data within aparticular window of the data, etc.

Some differences between seismic and EM noise should be noted. Forexample, whereas in seismic data, seismic noise may be substantial, andcaution must be used to avoid amplifying noise in an attempt to amplifyattenuated signal, this is a smaller problem in marine EM data, sincethe overlying water layer serves to attenuate natural noise in theappropriate frequency band. Further, source-generated noise (e.g.,following non-direct wave paths) can be managed using appropriate surveydesign of source-signature and source-receiver offset, to minimize thisproblem. Finally, whereas in seismic data, dispersion is generally aweak effect (and may be neglected in some applications), in EM data itis strong and must be handled properly. However, since the preferredcorrection is of the deterministic functional form discussed below, itis generally not a major source of uncertainty.

As a next preferred step 421, in some preferred embodiments the sortedand shaped t-CSEM traces will be stacked to further enhance the commonsignal contained therein. A conventional average/sum-type stackingoperation could be performed or, for example, well known stackingalternatives such as weighted, median, etc., stacks. Note it is known inthe prior art to stack EM traces that are obtained by repeating the samesource-receiver experiment. However, stacking within the context of theinstant invention refers to combining EM traces from differentsource-receiver pairs that have been time-shifted to account fortravel-time differences.

In addition, other operations which do not necessarily rely on thetime-distance characteristics of the data might be applied. For example,longitudinal median filters might be utilized to remove spikes from theinput data. (Note that, in the seismic arts, “median filtering” is asingle-trace, sliding-window operation, different from an operationknown in the electromagnetic arts as “median stacking” [or, moregenerally, “selective stacking”, cf., e.g. Strack, 1992, citedpreviously], which is applied to a set of replicate traces taken withthe same source and receiver positions). Other commonly used noisereduction filters such as a time-variant smoothing filter (Strack, 1992,cited previously) may also be applied. Those of ordinary skill in theart will recognize that many such noise-reduction/data enhancementoperations might be performed on the t-CSEM data. It is preferable, andin most cases important, that this noise be removed prior to the nextprocedure, wherein the data are corrected for dispersion and attenuationaccording to its path of energy propagation.

As a next preferred procedure, at 425, a correction for dispersion andattenuation will preferably be applied to the t-CSEM data. Thisprocedure is of particular importance to the effective operation of theinstant invention. The principal elements in this process 425 areillustrated in FIG. 6. The preferred dispersion/attenuation correction600 is performed as follows. First, the input data will be read orotherwise accessed (at 605). Next, an arrival will be selected withinthe t-CSEM data, and an energy travel path between the source and eachof the receivers determined for such arrival (at 610). Note that, inconjunction with this procedure, energy traveling along different pathsshould have been attenuated or separated by the noise-reductionoperations discussed previously. Further, note that in conjunction withthis procedure, it might be desirable to calculate a velocity functionfrom the t-CSEM data (step 420). Those of ordinary skill in the art willrealize that such functions are routinely calculated for seismic data,and similar techniques could be applied here (e.g., picking arrivals,coherency velocity analyses, constant-velocity stacks, tomographicanalysis, logs, etc.). However it is determined, preferably at least asingle-valued velocity function (i.e., a velocity function that variesonly with time, or depth) will be determined from the input data. Itwould be preferable in most cases, though, to use a 2-D or 3-D velocityfunction (i.e., one that varies in 2 or 3 dimensions), such as wouldtypically be determined for similar seismic data. Such a velocityfunction would necessarily vary with frequency (at each position)according to the principles set out below.

In some preferred embodiments, the energy travel path will be calculatedby using ray tracing between the source and receiver using standardray-tracing principles (e.g., Snell's law) applicable to seismic data.One object of the ray trace calculation is to obtain the length of thetravel path “R₀” between the source and receiver for a given arrival inthe data.

Next, a reference frequency ω₀ (i.e. a specific angular frequency, inunits of inverse natural time) will be selected 615 for the event(arrival) under consideration. The reference frequency will preferablybe selected by calculating a Fourier-transform amplitude spectrum of theevent in question and selecting the natural frequency that has thelargest magnitude associated therewith (see, e.g., 810 in FIG. 8).

Finally, the process of the instant invention will preferably correctthe t-CSEM traces for energy attenuation and dispersion at eachfrequency according to the square root of frequency using Q=½, where “Q”is the well known “quality factor” of seismic prospecting and analysis.The preferred method of correcting for attenuation and dispersion ateach natural frequency ω is via a convolution (filtering) using a filterwhose Fourier-domain representation is, at each frequencyexp[+ωR ₀ /V _(phs) +iω(R ₀ /V _(phs) −R ₀ /V ₀)],whereV ₀ ≡V _(phs)(ω₀)=√{square root over (2ω₀ρ/μ)},R₀ is the length of the travel path from the source to the selectedevent, and ω₀ is the reference frequency. Note that the first summand inthe exponential is intended to correct for the effects of attenuationand the second for dispersion and, in fact, it would bepossible—although not preferred—to correct for one effect, the other, orboth according to how the previous equation is applied to the data.V_(phs) is preferably defined as followsV _(phs)(ω)=√{square root over (2ωρ/μ)},where ρ is the formation resistivity, and μ is the magnetic permeabilityof the intervening rock units. If these material parameters vary alongthe inferred signal travel path, the filter definition above must beadjusted accordingly, as will be understood by those skilled in theseismic arts. Those skilled in the seismic arts will be familiar with acorresponding seismic expression, wherein the leading term (compare withthe above) isexp[+wR ₀/2QV _(phs)]where, in the seismic context, the quality factor Q is an unknownphysical parameter to be determined. A distinguishing characteristic oft-CSEM propagation is that (from well-established theory) Q=½identically, i.e., at least in theory it is not a material parameter,and will generally not need to be determined by the explorationist. Infact, under this assumption, it disappears from the filter definedabove, since it is multiplied by the constant “2” in the denominator.

With that said, those familiar with the seismic or electromagnetic artswill be aware that it is the combinationωR ₀ /V _(phs)(ω)=ωR ₀/2Q _(EM) V _(phs)(ω)which is most important, rather than the values of its constituentparts. If the path length R₀, or the velocity V_(phs) is uncertain, onemight attempt to account for such uncertainty by adjusting the value ofQ_(EM) away from its theoretical value of 2. This should be viewed as anempirical procedure, unsupported by theory, but within the ambit of theinstant invention.

Note that the preceding convolution goes to the heart of one aspect ofthe instant invention. After correction for attenuation/dispersion asdescribed above, the t-CSEM data traces will have been converted so thatthey can be imaged and interpreted in a manner similar to seismic datatraces by exploiting their time-distance characteristics.

Now, given that the t-CSEM data, and especially t-CSEM data acquired andprocessed as explained above, have the time-distance characteristics ofseismic data, traditional and non-traditional methods of seismic imaging(shown at 500) will preferably next be applied. For example, and as isillustrated in FIG. 5, as an initial procedure it is preferred that animaging algorithm be selected (at 505). Imaging algorithms include, forexample, stacking, or migration (in time or depth, prestack orpoststack). More broadly, other processes that sharpen or otherwiseenhance the image might also be performed, such as inversion of the datafor the parameters of predetermined models, etc. As a consequence, whenthe term “imaging algorithm” is used herein, that usage should bebroadly construed to include any algorithm that is suitable for use onseismic data and that is designed to improve the quality of the imagethat is obtained therefrom including, without limitation, any sort ofprocessing, including deconvolution, wavelet shaping, statics, velocityanalysis, time-offset correction (e.g., NMO), filtering, muting in awindow, pre-stack imaging (e.g., pre-stack migration, DMO, etc.),stacking, gain correction, post-stack imaging (e.g., post-stackmigration), or inversion, as well as the generation of any attribute,for example instantaneous phase, Amplitude Variation with Offset, etc.

After an imaging algorithm has been selected, the transformed t-CSEMdata will be read (at 510), organized (at 515), and processed (at 525)using imaging procedures applicable to seismic data. Note that theorganization 515 might include sorting the filtered t-CSEM data into CMPgathers in preparation for stacking, sorting to common-offset gathers,etc. The algorithms for performing such 2-D and/or 3-D operations onseismic data are very well known to those of ordinary skill in theseismic arts.

In those instances where the selected processing algorithm requires thatthe user provide a velocity function (e.g., both stack and migrationrequire a velocity function), such might be obtained by any number ofconventional methods using the processed t-CSEM traces as though theywere unstacked seismic traces, and analyzing, for example, moveout todetermine a velocity function. The velocity function may be of isotropicor anisotropic nature. If the velocity function is anisotropic, it mayindicate polar anisotropy or azimuthal anisotropy. If azimuthallyanisotropic, certain complications arise. See, for example, the seismicshear-wave discussion in Thomsen (2002), i.e., Thomsen, L., 2002,Understanding Seismic Anisotropy in Exploration and Exploitation,Society of Exploration Geophysicists, for a discussion of suchcomplications in the seismic context.

Note that if such has not been performed already, the correction fordispersion and attenuation discussed previously (at 520 and FIG. 6) ispreferably performed before the actual imaging algorithm is applied (at525).

Furthermore, the invention disclosed herein discusses t-CSEM in terms ofseismic traces organized into “CMP” or common-offset gathers, that isdone for purposes of specificity only and not out of any intent to limitthe instant invention to operation on only that sort of gather. So,within the context of this disclosure, the term gather is used in thebroadest possible sense of that term, and is meant to apply toconventional 2-D and 3-D CMP gathers, as well as to other sorts ofgathers that might include, without limitation, Common-Image-Pointgathers, Common-Receiver gathers, Common-Source Gathers, Common-Offsetgathers, etc., the most important aspect of a “gather” being that itrepresents a collection of unstacked data traces from either a 2-D or3-D survey, organized according to a principle based on one or moreaspects of the survey geometry.

Additionally, it should be noted that although most of the examplesgiven herein were concerned with marine surveys, technology of theinstant invention could be employed onshore, if the attendant logisticalissues (e.g., coupling of sources and receivers to the ground) areresolved. See Wright et al., U.S. Pat. No. 6,914,433, for additionaldiscussion.

Additionally, we envision the processing of the electromagnetic data tobe done either sequentially or concurrently to seismic data processingcovering the same volume (if available). When processed concurrently, itcan be done in cooperative fashion in which one method feedsintermediate results to the other to develop constraints, or in a moreformalized integrated fashion using well known methods such as jointinversion. (Strack, 1992, cited previously).

Finally, FIG. 10 illustrates conceptually how EM traces might beprocessed by the instant invention to provide a view of ahydrocarbon-containing unit in the subsurface. As is generally indicatedin this figure, with acquisition and processing according to the instantinvention EM will generally take the characteristics of—and beinterpreted very much like—conventional seismic data.

Technical Discussion

The instant invention concerns CSEM, and in particular t-CSEMtechniques, to be applied in both land and marine contexts, although thepreferred embodiment is the marine context. The transient-sourcecharacter of t-CSEM techniques is similar to that of seismic techniques,which typically employ impulsive (marine) or “swept” (land) sources. Infact, a broad understanding that seismic techniques and electromagnetictechniques are somehow analogous is also well known, e.g., see Ursin, B,1983, Review of elastic and electromagnetic wave propagation in layeredmedia: Geophysics, 48, 1063-1081. However, the analogy is not exact, sothat many seismic techniques cannot be applied to EM data withoutmodification.

In more particular, it is well known in seismic data processing thatseismic data for hydrocarbon exploration, appraisal, production anddevelopment should be processed to suppress the noise, while enhancingthe signal, if possible. Often, this is done by recognizing thetime-distance characteristics of such data. As examples:

-   -   The data may be f-k filtered. Here, the time-distance        characteristics of the data are explicitly involved, since the        filtering is done simultaneously in terms of frequency (the        complement of time) and wave number (the complement of        distance).    -   The data may be τ-p filtered.    -   The data may be median or robust filtered.    -   The data in a window delimited in time and vector or scalar        offset may be muted.    -   The data may be corrected for dispersion and attenuation.        These concerns have been fully understood by seismic        practitioners for decades, but not at all by EM practitioners,        since    -   most Controlled-Source ElectroMagnetic practice in the        hydrocarbon context has been f-CSEM, hence unable to utilize the        time-distance characteristics of the data.    -   most t-CSEM practice has been very primitively designed, using        few receivers so that proper time-distance processing is not        possible.

Science Background

As a starting point, consider the basic physics which establishes theEM-seismic analogy; this in itself (although well-established) isnon-trivial and not understood by many expert practitioners of eitherseismics or EM.

Seismics

Starting first with anelastic seismic theory, the simplest approach isthrough the wave equation for an isotropic homogeneous medium:δ∂² {right arrow over (u)}=M∇ ² {right arrow over (u)}  (1)where {right arrow over (u)}({right arrow over (x)},t) is the particledisplacement vector (variable in space {right arrow over (x)} andnatural time t), and ∇ and ∂ are conventional notation for partialdifferential operators in space and time, respectively. The medium ischaracterized by M (the deformation modulus) and δ (the density). Forelastic media, M is real (and different for different wave-types); foranelastic media it is complex.

We seek harmonic solutions to (1) of the form{right arrow over (u)}({right arrow over (x)},ω)={right arrow over (u)}₀(ω)G _(defm)({right arrow over (x)})exp(iωt)  (2)In elastic wave theory, the sign of the phase iωt in the oscillatorysecond term above is immaterial, but in anelastic wave theory, it iscrucial that it be chosen as above, so that (with positive angularfrequency ω) phase increases with increasing time.

Then from (1) and (2), the equation for the spatial deformation functionG_(defm) is:(∇² +K ²)G _(defm)=0  (3)where the wavenumber K is given by:K=+ω√{square root over (δ/M)}  (4)with solution G_(defm)(R)=exp(−iKR) for propagation in any radialdirection R=|{right arrow over (x)}|. The positive square root is theonly root that is physically permissible, according to the Second Law ofThermodynamics.

Now separating the real and imaginary parts of M, the modulus (whetherfor P or S waves) can be written in complex form asM=M _(R) +iM _(I)  (5)The (implicit) frequency-dependences of M_(R) and M_(I) are connected bythe “Kramers-Kroenig relations”; these dependences are physical (notmathematical) in nature, and are poorly understood, in general, with acomplicated frequency dependence depending on poorly known physicalparameters.

It is conventional (cf., e.g., O'Connell and Budianski, 1978) to definethe quality factor Q_(defm) for deformation through: $\begin{matrix}{Q_{defm} \equiv \frac{M_{R}}{M_{I}}} & (6)\end{matrix}$It is a requirement of the Second Law of Thermodynamics that Q_(defm) isnon-negative. (Further, it is a requirement for deformational stabilitythat M_(R) is non-negative, hence M_(I) is also non-negative.)

The expressions for the real and imaginary parts of K involve fourthpowers of Q_(defm), and are not very enlightening. Instead, we definethe real and imaginary parts of the velocity v by: $\begin{matrix}{v = {{v_{R} + {{\mathbb{i}}\quad v_{I}}} = {\sqrt{M/\delta}{with}}}} & (7) \\{{v_{R} = {\sqrt{\frac{M}{\delta}}\left\lbrack {1 + {\left( {\sqrt{1 + {1/Q_{defm}^{2}}} - 1} \right)/2}} \right\rbrack}^{{+ 1}/2}}{and}} & \left( {8a} \right) \\{v_{I} = {\frac{1}{2Q_{defm}}{\sqrt{\frac{M}{\delta}}\left\lbrack {1 + {\left( {\sqrt{1 + {1/Q_{defm}^{2}}} - 1} \right)/2}} \right\rbrack}^{{- 1}/2}}} & \left( {8b} \right)\end{matrix}$so that the real and imaginary parts of the wave number are given, inthese terms, by $\begin{matrix}{K = {\frac{\omega}{v} = {{\frac{\omega}{v_{R}^{2} + v_{I}^{2}}\left( {v_{R} - {{\mathbb{i}}\quad v_{I}}} \right)} \equiv \left( {\frac{\omega}{v_{phs}} - {i\quad\alpha}} \right)}}} & (9)\end{matrix}$where the last expression implicitly defines the (real) seismic phasevelocity v_(phs) and attenuation coefficient α.

Finally, the plane wave (2) becomes{right arrow over (u)}({right arrow over (x)},ω)={right arrow over (u)}(ω)exp[−αR]exp[iω(t−R/v _(phs))]  (10)The wave attenuates as it propagates (with the opposite phaseconvention, it would grow exponentially instead).

This entire development is valid for any magnitude of Q_(defm). However,in normal seismic contexts, the attenuation is small, i.e., Q_(defm)>>1(and the corresponding frequency dependence of M_(R) and M_(I), and ofv_(phs) and Q_(defn), is modest). In the limit of large Q_(defm),$\begin{matrix}{v_{phs} \approx v_{R} \approx \sqrt{M/\delta}} & \left( {11a} \right) \\{\alpha \approx {v_{I}/v_{R}^{2}} \approx \frac{\omega}{2Q_{defm}v_{phs}}} & \left( {11b} \right)\end{matrix}$so that the wave number is approximately: $\begin{matrix}{K \approx {\frac{\omega}{v_{phs}}\left( {1 - \frac{\mathbb{i}}{2Q_{defm}}} \right)}} & (12)\end{matrix}$

In fact, an operational definition of seismic attenuation (independentof broader considerations of deformation in other contexts) can be basedupon (12) instead of (6), by defining $\begin{matrix}{K \equiv {\frac{\omega}{v_{phs}}\left( {1 - \frac{\mathbb{i}}{2Q_{seis}}} \right)}} & (13)\end{matrix}$regardless of the magnitude of Q_(seis), with corresponding changes tothe definitions of v_(phs) and Q_(defn). If Q_(seis) is small, then thefrequency dependence (the “dispersion”) of v_(phs) and Q_(seis) islarge. Whether or not Q_(seis) is small, the displacement can be writtenas{right arrow over (u)}({right arrow over (x)},ω)={right arrow over (u)}₀(ω)exp[−ωR/2v _(phs) Q _(seis)]exp[iω(t−R/v _(phs))]  (14)

There is a vast literature developing methods to use (14) for imagingand characterizing the earth's subsurface, under the restriction thatQ_(seis)=∞. There is a small literature developing methods to so use(14), under the assumption that Q_(seis) is large but finite, mostlydirected towards adjusting seismic data to remove the effects of finiteQ_(seis).

Electromagnetics

Two of Maxwell's equations as applied to a uniform isotropic medium maybe written as:∇×{right arrow over (E)}=−μ∂{right arrow over (H)}∇×{right arrow over (H)}=(σ+∈∂){right arrow over (E)}  (15)where {right arrow over (E)} is the electric field (variable in space{right arrow over (x)} and time i), {right arrow over (H)} is themagnetic field, and the medium is characterized by ∈ (the dielectricconstant), μ (the magnetic permeability), and σ (the electricalconductivity). These equations have been well known for over a century,and form the basis for all classical electromagnetic phenomena, in thelinear range where Ohm's “law” applies.

Taking the curl (∇×) differential operation on these equations, andusing the well-known differential identity [∇×(∇×)=(∇·)−∇²] to eliminate{right arrow over (H)}, yields Maxwell's wave/diffusion equation for theelectric field:∇² {right arrow over (E)}−μ∈∂ ² {right arrow over (E)}−μσ∂{right arrowover (E)}=0  (16)and an identical equation for {right arrow over (H)}, showing that bothmust propagate together.

We seek harmonic solutions to (16) of the form{right arrow over (E)}({right arrow over (x)},ω)={right arrow over (E)}₀(ω)G _(EM)({right arrow over (x)})exp(iωt)  (17)Note that this is the same convention as that used above, in the seismiccontext, and opposite to that used by Ursin 1983, cited previously.

The spatial electromagnetic function is the solution to(∇² +k ²)G _(EM)=0  (18)where the wavenumber k is given by $\begin{matrix}{k = {{\omega\sqrt{{\mu ɛ}\left( {1 - {{\mathbb{i}\sigma}/{\omega ɛ}}} \right)}} = {\frac{\omega}{nc}\sqrt{1 - {{\mathbb{i}}\frac{({nc})^{2}\mu}{\omega\rho}}}}}} & (19)\end{matrix}$In the rearrangement on the right ρ=1/σ is the electrical resistivity, nis the “index of refraction”, and c is the speed of light in vacuum,about 3*10⁵ km/s; nc=1/√{square root over (μ∈)}. In a vacuum, ρ=∞, andn=1, so that the second term on the right hand side of (19) is zero, andc=ω/k is the speed of light.

At high frequencies in rock (the “displacement current regime”), thesecond term in (19) is small, and the wave propagates as radar, withvelocity nc. But, at these high frequencies, the wavelengths are veryshort, so that the small second term attenuates the wave to virtuallynothing after a short penetration distance.

At sufficiently low frequencies (the “conduction current regime”), thesecond term dominates, so thatk≅√{square root over (−iωμ/ρ)}=√{square root over(ωμ/2ρ)}(1−i)≡κ(1−i)  (20)defining the scalar wavenumber κ. This occurs whenever $\begin{matrix}{{\omega ⪡ \omega_{crit} \equiv \frac{({nc})^{2}\mu}{\rho}};} & (21)\end{matrix}$this is quantified further below.

Under these conditions, the phase velocity is:$V_{phs} = {\frac{\omega}{\kappa} = \sqrt{\frac{2{\omega\rho}}{\mu}}}$and the group velocity is $\begin{matrix}{V_{grp} = {\frac{\partial\omega}{\partial\kappa} = {2V_{phs}}}} & (22)\end{matrix}$

For non-magnetic rocks, μ=μ₀=4π10⁻⁷ H/m, the magnetic permeability ofvacuum. For typical sedimentary rocks, the resistivity is of the orderof ρ=1 ohm-m, so that at a frequency of 1 Hz the phase velocity V_(phs)is 3.16 km/s, comparable to the speed of sound. ρ may be a weak functionof ω, but the main frequency dependence of V_(phs) is the explicitsquare-root dependence shown above.

Using (22) in (21), the critical frequency separating the displacementand conduction regimes is${f_{crit} \equiv \frac{({nc})^{2}\mu}{2\quad\pi\quad\rho}} = {{2{f_{0}\left( \frac{nc}{V_{phs}\left( f_{0} \right)} \right)}^{2}} \approx {{2 \cdot 10^{8}}\quad{Hz}}}$where the numerical result assumes f₀=1 Hz, and n=0.1. This is so highthat all the frequencies used to probe deeply into the earth are wellwithin the conduction regime, justifying the use of Equation (20).

At such low frequencies, the plane-wave solution to (16) is$\begin{matrix}{\quad\begin{matrix}{{\overset{\rightarrow}{E}\left( {R,\omega} \right)} = \quad{{\overset{\rightarrow}{E}}_{0}{\exp\quad\left\lbrack {{- \kappa}\quad R} \right\rbrack}{\exp\quad\left\lbrack {{\mathbb{i}}\left( {{\omega\quad t} - {\kappa\quad R}} \right)} \right\rbrack}}} \\{= {{\overset{\rightarrow}{E}}_{0}{\exp\quad\left\lbrack {{- \omega}\quad{R/V_{phs}}} \right\rbrack}\quad{\exp\quad\left\lbrack {{\mathbb{i}}\quad\omega\quad\left( {t - {R/V_{phs}}} \right)} \right\rbrack}}}\end{matrix}} & (23)\end{matrix}$

Of course, there is a similar expression for the magnetic field {rightarrow over (H)}. This EM expression bears a strong resemblance to theseismic expression (14); the principal differences are:

-   -   In the seismic case, there is only one field, whereas in the EM        case, {right arrow over (E)} and {right arrow over (H)} are        coupled, and propagate together.    -   The first (attenuating) term in the EM case lacks a factor ½Q in        the exponent; this is equivalent to defining an electromagnetic        Q_(EM)=½.    -   The EM phase velocity V_(phs) is strongly frequency dependent        (cf. Eqn. (22)), whereas the seismic phase velocity V_(phs) is        only weakly frequency dependent.

Q-Deconvolution of Electromagnetic Waves

In the instant invention, as a first step CSEM data are acquired:

-   -   preferably in a marine environment, with a source towed near to        the seafloor;    -   preferably with an impulsive source signature, or other source        signature that is suitable for time-domain processing; and,    -   preferably with many seafloor receivers distributed with a        variety of source-receiver offsets.        Those of ordinary skill in the art will recognize that many        variants and alternatives to the foregoing preferences are        certainly possible and well within the scope of the instant        invention.

Next, the raw EM data records are preferably preprocessed (in variousways familiar to those knowledgeable in conventional CSEM processingmethods) for instrument corrections, navigation assignment, water-waveremoval, etc.

The effects of EM attenuation and dispersion are then preferably removedfrom the data. Preferably, a convolution-based method will be utilized;other implementations of the basic idea (e.g., via migration, arestraightforward).

In this exploration context, the propagation distance R can be specifiedby assuming a single reflection within a uniform layer, approximated byR=√{square root over (t₀ ²V_(phs) ²+x²)} where t₀ is the time of arrivalof the event in (2) and x is the source-receiver offset. (More complexrelations defined by an inhomogeneous and/or anisotropic subsurface, areobviously possible, obvious to those skilled in the art, and included inthis invention.)

Because of the dispersion (cf. (22)), the energy arrives over anextended time interval, even though the bandwidth of the source isfinite. Since we want to localize the arrival of the Q-corrected energy,we add and subtract a constant-velocity term in (23): $\begin{matrix}\begin{matrix}{\quad{{\overset{\rightarrow}{E}\left( {R,\omega} \right)} = {{\overset{\rightarrow}{E}}_{0}{\exp\quad\left\lbrack {{- \omega}\quad{R/V_{phs}}} \right\rbrack}\quad{\exp\quad\left\lbrack {{\mathbb{i}}\quad{\omega\left( {t - {R/V_{phs}} +} \right.}} \right.}}}} \\\left. \left. {{R_{0}/V_{0}} - {R_{0}/V_{0}}} \right) \right\rbrack \\{= {{{\overset{\rightarrow}{E}}_{0}\exp\quad\left\lbrack {- \omega}\quad{R/V_{phs}} \right.} - {{\mathbb{i}}\quad\omega\quad\left( {{R/V_{phs}} -} \right.}}} \\{\left. \left. {R_{0}/V_{0}} \right) \right\rbrack{\exp\quad\left\lbrack {{\mathbb{i}}\quad\omega\quad\left( {t - {R_{0}/V_{0}}} \right)} \right\rbrack}}\end{matrix} & (24)\end{matrix}$whereV ₀ ≡V _(phs)(ω₀)=√{square root over (2ω₀ρ/μ)},R ₀ =√{square root over (t ⁰ ² V ⁰ ² +x ² )},and ω₀ is a reference frequency, typically chosen near the center of thereceived bandwidth.

Multiplying this Fourier transform by the inverse of the first factoryields,{right arrow over (E)}(R,ω)exp[+ωR/V _(phs) +iω(R/V _(phs) −R ₀ /V₀)]={right arrow over (E)} ₀(ω)exp[iω(t−R ₀ /V ₀]  (25)Upon inverse Fourier transformation, the left side of (25) defines thepreprocessed data {right arrow over (E)}(R,ω), convolved with a filterwhich simultaneously corrects for the attenuating and dispersing effectsof the propagation. The right side represents a band-limited impulsivearrival, with a delay given by R₀/V₀. The required filter which producesthis has representation (in the Fourier domain)exp[+ωR ₀ /V _(phs) +iω(R ₀ /V _(phs) −R ₀ /V ₀)]  (26)

Implicit in this expression is the source-receiver offset x (known), andthe arrival time t₀, which shows that the filter is a dynamic one,varying in its definition as a function of trace time and energypropagation path. The filter (25) diverges at high frequency; inpractice this is not a problem because the incident bandwidth islimited, i.e., {right arrow over (E)}₀(ω) is zero at high frequencies.Hence, in practice, the filter above may be tapered appropriately athigh frequency, so that high-frequency noise is not unduly amplified.

CONCLUSIONS

Finally, although the instant invention has been described herein asoperating on EM traces that are maintained in natural time (in contrastto the methods of the prior art that employ an initial transformation tolog-time followed by the application of a natural-time seismicalgorithm), those of ordinary skill in the art will recognize that mostseismic time-distance processes can be rewritten to function in other(e.g., log-time) domains. As such, for purposes of the instant invention“natural time” will be additionally construed to include instances wherethe EM data have been transformed to another time or offset dimensionand a time-distance seismic algorithm that typically would have operatedon natural time data has been correspondingly recoded to operate on thetransformed EM data.

Further, those of ordinary skill in the art will recognize that,although the methods discussed herein in connection with Q deconvolutionare best understood conceptually via their expression in the frequencydomain, there is an equivalent time-domain algorithm that wouldaccomplish the same result. That is, theoretical interchangeabilitybetween algorithms that operate in the frequency domain and the timedomain is well known. As a consequence, when the instant invention issaid to operate on one or more frequencies, that language should bebroadly interpreted to include cases where the algorithm operates in thefrequency domain, as well as instances where a substantially equivalentoperation is performed in the time domain.

While the invention has been described and illustrated herein byreference to a limited number of embodiments in relation to the drawingsattached hereto, various changes and further modifications, apart fromthose shown or suggested herein, may be made therein by those skilled inthe art, without exceeding the scope of what has been invented, thescope of which is to be determined only by reference to the followingclaims.

1. A method of processing EM data for use in geophysical exploration ofa predetermined volume of the earth containing structural andstratigraphic features conducive to the generation, migration,accumulation, or presence of hydrocarbons, comprising the steps of: (a)acquiring an EM survey that covers at least a portion of saidpredetermined volume of the earth, said survey comprising a plurality ofEM traces; (b) selecting at least one of said EM traces; (c) selecting aplurality of different frequencies; (d) selecting a value of a parameterQ, wherein said parameter Q is a quality factor related to atransmission of EM data; (e) correcting each of said at least oneselected EM traces for at least one of attenuation and dispersion ateach of said selected plurality of frequencies according to saidparameter Q, thereby producing a plurality of processed EM traces; and,(f) writing at least a portion of said processed EM traces to computerstorage.
 2. A method according to claim 1, wherein said parameter Q isapproximately equal to ½.
 3. A method according to claim 1, wherein step(e) comprises the steps of: (e1) selecting a reference frequency ω₀.(e2) for each of said selected EM traces, (i) selecting one of saidplurality of frequencies, wherein said selected frequency is representedby ω, (ii) correcting said selected EM trace for attenuation anddispersion according to the following formula:exp[+ωR ₀/2QV _(phs) +iω(R ₀ /V _(phs) −R ₀ /V ₀)],  where, R₀ is alength of a travel path from an EM source of said selected EM trace to areceiver sensing said EM source,  where V₀≡V_(phs)(ω₀)=√{square rootover (2ω₀ρ/μ)},  where${V_{phs} = \sqrt{\frac{2\quad\omega\quad\rho}{\mu}}},$  where ρ is asubsurface resistivity,  where μ is a subsurface magnetic permeability,and, (iii) performing steps (i) and (ii) above for each of said selectedplurality of frequencies, and, (e3) performing at least step (e2) foreach of said selected EM traces, thereby producing a plurality ofprocessed EM traces.
 4. A method according to claim 1, wherein saidcomputer storage is selected from a group consisting of a magnetic disk,a magnetic tape, an optical disk, a magneto-optical disk, RAM, andnon-volatile RAM.
 5. A method according to claim 1, further comprisingthe step of: (h) viewing at least a portion of said processed EM traceson a display device.
 6. A device adapted for use by a digital computerwherein a plurality of computer instructions defining the method ofclaim 1 are encoded, said device being readable by said digitalcomputer, said computer instructions programming said digital computerto perform said method, and, said device being selected from the groupconsisting of computer RAM, computer ROM, a PROM chip, flash RAM, a ROMcard, a RAM card, a floppy disk, a magnetic disk, a magnetic tape, amagneto-optical disk, an optical disk, a CD-ROM disk, or a DVD disk. 7.A method according to claim 1, wherein said EM data traces are selectedfrom a group consisting of CSEM data traces, f-CSEM data traces, andt-CSEM data traces.
 8. A method according to claim 1, wherein step (e)comprises the steps of: (e1) correcting each of said at least oneselected EM traces for attenuation and dispersion at each of saidselected plurality of frequencies according to said parameter Q, therebyproducing a plurality of corrected EM traces, and, (e2) processing saidcorrected EM traces with at least one seismic imaging algorithm, therebyproducing a plurality of processed EM traces.
 9. A method according toclaim 8, wherein each of said at least one seismic imaging algorithms isselected from a group consisting of muting, deconvolution, waveletshaping, statics, velocity analysis, time-offset correction, NMO,frequency filtering, pre-stack imaging, pre-stack migration, DMO,stacking, gain correction, post-stack imaging, post-stack migration,AVO, and attribute generation.
 10. A method according to claim 1,comprising the further step of: (g) interpreting said processed EMtraces for a purpose of exploration for hydrocarbons within saidpredetermined volume of the earth.
 11. A method of collecting andprocessing EM data for use in geophysical exploration within apredetermined volume of the earth containing structural andstratigraphic features conducive to the generation, migration,accumulation, or presence of hydrocarbons, comprising the steps of: (a)collecting an EM survey that images at least a portion of saidpredetermined volume of the earth, said survey comprising a plurality ofEM traces; (b) selecting at least one of said EM traces, each of saidselected EM traces having a source-receiver distance associatedtherewith, and each of said selected EM traces having a plurality of EMsamples organized in natural time associated therewith; (c) selecting atleast one time-distance processing algorithm; (d) applying said at leastone time-distance processing algorithm to said selected EM traces andsaid samples associated therewith using said at least one time-distanceprocessing algorithm at least according to said associatedsource-receiver distances and said selected EM trace samples, therebyproducing a plurality of processed EM traces; and, (e) writing at leasta portion of said processed EM traces to computer storage.
 12. A methodaccording to claim 11, wherein said at least one time-distanceprocessing algorithm is selected from a group consisting of velocityfiltering, muting in a window, f-k filtering, NMO, DMO, time migration,depth migration, velocity estimation, tomography, and, tau-p filtering.13. A method according to claim 11, wherein step (d) comprises the stepsof: (d1) selecting a plurality of different frequencies, (d2) selectinga value of a parameter Q, wherein said parameter Q is a quality factorrelated to a transmission of EM data, (d3) correcting each of said atleast one selected EM traces for at least one of attenuation anddispersion at each of said selected plurality of frequencies accordingto said parameter Q, thereby producing a corresponding plurality ofcorrected EM traces, each of said corrected EM traces having a pluralityof corrected samples associated therewith, and, (d4) processing saidcorrected EM traces and said associated corrected samples using said atleast one time-distance processing algorithm at least according to saidassociated source-receiver distances, thereby producing a plurality ofprocessed EM traces.
 14. A method according to claim 13, wherein saidparameter Q is approximately equal to ½.
 15. A method according to claim11, wherein said computer storage is selected from a group consisting ofa magnetic disk, a magnetic tape, an optical disk, a magneto-opticaldisk, RAM, and non-volatile RAM.
 16. A method according to claim 11,further comprising the step of: (h) viewing at least a portion of saidprocessed EM traces on a display device.
 17. A device adapted for use bya digital computer wherein a plurality of computer instructions definingthe method of claim 11 are encoded, said device being readable by saiddigital computer, said computer instructions programming said digitalcomputer to perform said method, and, said device being selected fromthe group consisting of computer RAM, computer ROM, a PROM chip, flashRAM, a ROM card, a RAM card, a floppy disk, a magnetic disk, a magnetictape, a magneto-optical disk, an optical disk, a CD-ROM disk, or a DVDdisk.
 18. A method according to claim 11, wherein said EM data tracesare selected from a group consisting of CSEM data traces, f-CSEM datatraces, and t-CSEM data traces.
 19. A method of geophysical explorationwithin a predetermined volume of the earth, wherein is provided an EMsurvey that images at least a portion of the predetermined volume of theearth, said EM survey containing at least two EM traces therein,comprising the steps of: (a) selecting at least one of said EM traces;(b) selecting a plurality of frequencies; (c) correcting each of said atleast one selected EM traces for attenuation and/or dispersion at eachof said selected plurality of frequencies, thereby producing a pluralityof processed EM traces; (d) processing said EM traces with at least oneseismic imaging algorithm, thereby producing a plurality of seismicprocessed EM traces; and, (e) writing at least a portion of said seismicprocessed EM traces to computer storage.
 20. A method according to claim19, wherein step (d) comprises the step of: (d1) processing said EMtraces with at least one seismic imaging algorithm, wherein said atleast one of said at least one seismic imaging algorithms is atime-distance algorithm, thereby producing a plurality of seismicprocessed EM traces.
 21. A method according to claim 20, wherein saidtime-distance processing algorithm is selected from a group consistingof muting, NMO, DMO, time migration, depth migration, tau-p filtering,velocity estimation, tomography, and f-k filtering.
 22. A methodaccording to claim 20, wherein step (c) comprises the steps of: (c1)selecting a value of a parameter Q, wherein said parameter Q is aquality factor related to a transmission of EM data, and, (c2)correcting each of said at least one selected EM traces for attenuationat each of said selected frequencies according to said parameter Q,thereby producing a plurality of processed EM traces.
 23. A methodaccording to claim 22, wherein said parameter Q is approximately equalto ½.
 24. A method according to claim 21, wherein step (c) comprises thesteps of: (c1) selecting a reference frequency ω₀, (c2) for each of saidselected EM traces, (i) selecting one of said plurality of frequencies,wherein said selected frequency is represented by ω, (ii) correctingsaid selected EM trace for attenuation and dispersion according to thefollowing formula:exp[+ωR ₀/2QV _(phs) +iω(R ₀ /V _(phs) −R ₀ /V ₀)],  where, R₀ is alength of a travel path from said selected EM trace to an EM sourcegiving rise to said selected EM trace,  where V₀≡V_(phs)(ω₀)=√{squareroot over (2ω₀ρ/μ)},  where${V_{phs} = \sqrt{\frac{2\quad\omega\quad\rho}{\mu}}},$  where ρ is asubsurface resistivity, and,  where μ is a subsurface magneticpermeability, and, (iii) performing steps (i) and (ii) above for each ofsaid selected plurality of frequencies, and, (e3) performing at leaststep (e2) for each of said selected EM traces, thereby producing aplurality of processed EM traces.
 25. A method according to claim 21,wherein said computer storage is selected from a group consisting of amagnetic disk, a magnetic tape, an optical disk, a magneto-optical disk,RAM, and non-volatile RAM.
 26. A method according to claim 21, furthercomprising the step of: (g) viewing at least a portion of said processedEM traces on a display device.
 27. A device adapted for use by a digitalcomputer wherein a plurality of computer instructions defining themethod of claim 21 are encoded, said device being readable by saiddigital computer, said computer instructions programming said digitalcomputer to perform said method, and, said device being selected fromthe group consisting of computer RAM, computer ROM, a PROM chip, flashRAM, a ROM card, a RAM card, a floppy disk, a magnetic disk, a magnetictape, a magneto-optical disk, an optical disk, a CD-ROM disk, or a DVDdisk.
 28. A method according to claim 21, wherein said EM data tracesare selected from a group consisting of CSEM data traces, f-CSEM datatraces, and t-CSEM data traces.
 29. A method of geophysical explorationfor hydrocarbons within a predetermined volume of the earth, wherein isprovided an EM survey that images at least a portion of thepredetermined volume of the earth, said EM survey containing at leasttwo EM traces therein, comprising the steps of: (a) selecting at leastone of said EM traces; (b) selecting a plurality of frequencies; (c)selecting a reference frequency ω₀, (d) choosing one of said pluralityof selected frequencies, wherein said chosen frequency is represented byω, (e) correcting said selected EM trace for attenuation and dispersionaccording toexp[+ωR ₀ /V _(phs) +iω(R ₀ /V _(phs) −R ₀ /V ₀)],  where, R₀ is alength of a travel path from said selected EM trace to an EM sourcegiving rise to said selected EM trace,  where V₀≡V_(phs)(ω₀)=√{squareroot over (2ω₀ρ/μ)},  where${V_{phs} = \sqrt{\frac{2\quad\omega\quad\rho}{\mu}}},$  where ρ is asubsurface resistivity, and,  where μ is a subsurface magneticpermeability, (f) performing steps (d) and (e) above for each of saidselected plurality of frequencies, thereby creating a processed EMtrace; and, (g) using said processed EM trace to explore forhydrocarbons within the predetermined volume of the earth. (i)processing said EM traces with at least one seismic imaging algorithm,thereby producing a plurality of seismic processed EM traces; and, (e)writing at least a portion of said seismic processed EM traces tocomputer storage.
 30. A method according to claim 29, wherein saidcomputer storage is selected from a group consisting of a magnetic disk,a magnetic tape, an optical disk, a magneto-optical disk, RAM, andnon-volatile RAM.
 31. A method according to claim 21, further comprisingthe step of: (f) viewing at least a portion of said processed EM traceson a display device.
 32. A device adapted for use by a digital computerwherein a plurality of computer instructions defining the method ofclaim 29 are encoded, said device being readable by said digitalcomputer, said computer instructions programming said digital computerto perform said method, and, said device being selected from the groupconsisting of computer RAM, computer ROM, a PROM chip, flash RAM, a ROMcard, a RAM card, a floppy disk, a magnetic disk, a magnetic tape, amagneto-optical disk, an optical disk, a CD-ROM disk, or a DVD disk. 33.A method according to claim 29, wherein said EM data traces are selectedfrom a group consisting of CSEM data traces, f-CSEM data traces, andt-CSEM data traces.
 34. A method of conducting an unaliased EM survey toacquire data suitable for use in geophysical exploration of apredetermined volume of the earth containing structural andstratigraphic features conducive to the generation, migration,accumulation, or presence of hydrocarbons, comprising the steps of: (a)selecting a subsurface target within said predetermined volume of theearth; (b) determining at least one EM velocity proximate to saidsubsurface target, said at least one EM velocity being representative ofa velocity of an EM wave propagation proximate to said subsurfacetarget; (c) determining an approximate dip of said subsurface target;(d) using at least said at least one EM velocity and said approximatedip of said subsurface target to determine at least one of an EMsource-receiver near offset in said EM survey, an EM source-receiver faroffset in said EM survey, a number of EM traces in said EM survey, an EMtrace spacing in said EM survey and a discrete sampling interval innatural time, thereby designing an unaliased EM survey; (e) collectingEM data traces according to said designed EM survey; and, (f) using saidEM data traces for the exploration, appraisal, development, orsurveillance of hydrocarbons within said predetermined volume of theearth.
 35. A method according to claim 34, wherein said EM data tracesare selected from a group consisting of CSEM data traces, f-CSEM datatraces, and t-CSEM data traces.
 36. A method according to claim 34,further comprising the step of: (g) writing at least a portion of saidprocessed EM data traces to computer storage.
 37. A method according toclaim 36, wherein said computer storage is selected from a groupconsisting of a magnetic disk, a magnetic tape, an optical disk, amagneto-optical disk, RAM, and non-volatile RAM.
 38. A device adaptedfor use by a digital computer wherein a plurality of computerinstructions defining the method of claim 34 are encoded, said devicebeing readable by said digital computer, said computer instructionsprogramming said digital computer to perform said method, and, saiddevice being selected from the group consisting of computer RAM,computer ROM, a PROM chip, flash RAM, a ROM card, a RAM card, a floppydisk, a magnetic disk, a magnetic tape, a magneto-optical disk, anoptical disk, a CD-ROM disk, or a DVD disk.
 39. A method of geophysicalexploration for hydrocarbons beneath the surface of the earth,comprising the steps of: (a) selecting a subsurface target; (b)situating at least one EM receiver proximate to said subsurface target;(c) positioning an EM source within sensing ranging of at least one ofsaid at least one EM receivers; (d) activating said EM source accordingto a predetermined pattern, wherein said predetermined pattern isselected from a group consisting of a pseudo-random series of shortbinary pulses and a frequency sweep over a predetermined frequencyrange; (e) sensing said activated EM source via said at least one ofsaid EM receivers, thereby obtaining at least one EM trace; (f)processing said at least one EM traces according to said predeterminedpattern, thereby acquiring CSEM data suitable for use in geophysicalexploration beneath the surface the earth.
 40. A method of geophysicalexploration for hydrocarbons within a predetermined volume of the earthaccording to claim 39, wherein step (f) comprises the steps of: (f1)obtaining a pilot signal representative of said predetermined pattern,and, (f2) cross correlating said pilot trace with said at least one ofsaid EM traces, thereby acquiring CSEM data suitable for use ingeophysical exploration within said predetermined volume of the earth.41. A method of geophysical exploration for hydrocarbons within apredetermined volume of the earth according to claim 39, wherein saidpilot signal representative of said predetermined pattern is obtainedfrom a near-field receiver situated proximate to said EM source, saidnear-field receiver at least for sensing said activated EM source.
 42. Amethod of geophysical exploration for hydrocarbons within apredetermined volume of the earth according to claim 39, wherein furthercomprising the step of: (g) writing at least a portion of said processedEM data traces to computer storage.
 43. A method according to claim 39,wherein said at least one EM trace is selected from a group consistingof a CSEM trace, an f-CSEM trace, and a t-CSEM trace.